Natural gas and oil wells are often located in remote areas, hours away from maintenance and repair crews. Since the earliest days of the energy industry, pumpers have made the rounds of oil and gas facilities, checking equipment on Christmas trees and pumping units, recording production and gauging pressures, and liquid levels in tank batteries.

Pumpers still drive from wellsite to wellsite, tracking production and making sure that each well is operating efficiently and safely. But these days, a pumper is likely to carry a laptop in addition to a wrench, because computer-based field technology enables him to keep a watchful eye on production sites day and night, regardless of their location.

Supervisory control and data acquisition (SCADA) systems monitor and control production facilities throughout Chesapeake Energy Corp's wide-ranging operations. More than 12,000 Chesapeake-operated wells, representing 97% of the company's production, are equipped with automated systems.

"We have been using field-automation technology for about 10 years," says David Searls, Chesapeake's field automation specialist. "But in the past four years it has really taken off. Remote operations make us more efficient and safer, while freeing our pumpers to use their time on other issues, like improving production and safety."

Chesapeake puts its own twist on field automation, using it to measure and enhance natural gas and oil production through emissions and pressure controls. Most important, it can reduce safety hazards and environmental impact by immediately shutting in wells when measurements move outside accepted levels.

"Even with our rapid pace, we know what's going on at our well locations," says Jason Offerman, Chesapeake's manager of SCADA and field automation. "We do it through field automation that adds value to the company by monitoring and controlling wells, treatment facilities and pipelines in the absence of on-site operators."

According to Brian Babb, Chesapeake's vice president of production services, the system has four main functions—measurement, production, monitoring and control.

Through measurement, the system allows the company to compare volume data with data from purchasers, to verify and audit every thousand cubic feet of natural gas sold.

The system optimizes production through a computer box and keypad, and can open and close valves remotely, so a pumper is not required on-site to constantly tweak the well's plunger, gas lift and flow control settings.

Through monitoring, the system provides round-the-clock review of the well's overall performance. Flow measurement and level indicators monitor volumes at each telemetry site, enabling the company to predict how much gas is being produced and reduce the possibilities of spills or leaks.

And via controls, the system maintains safe operations at each well. For example, low pressure readings may indicate a leak, while high pressure readings could signal the possibility of a break.

In Chesapeake's operations, those functions are accomplished by the use of solar-powered computers located at each wellsite to gather measurements and data. The data moves through a distributed communications network system to the local field office and finally to company headquarters in Oklahoma City, where data is continuously provided to operating units from Pennsylvania to Wyoming.

Team effort

"We have 20 people in the SCADA and field-automation group in Oklahoma City who support dozens of field control technicians," Offerman says. "Our hardware components are bought and warehoused in Oklahoma, then shipped to the field offices. Our team collaborates with other engineering groups and the field to assess what needs to be done, how it needs to work and how to communicate with it. Then we design and test the systems and train our field operations personnel."

The process puts primary control at the field level where specialists like Gary Barnard, instrumentation and electrical (I&E) technician in Jane Lew, West Virginia, troubleshoot the automated systems after they are installed. Five years ago, his job did not exist. Today, Chesapeake has more than 30 I&E positions in 20 field offices, with openings across the company.

Barnard, who spent 24 years in the field as a pumper, is aware of how automated systems affect the work and safety of pumpers. "We didn't have automated systems when I was a pumper," he says. "They really make the pumper's life easier."

As the company shifts its emphasis from natural gas toward liquids, field operations are also shifting to accommodate the increased oil and wet gas production.

"One technology we use when producing oil or wet gas is a guided wave radar gauge that reads the level of liquid and gives us the volume of contents in the tank. From there, we can alert operators when levels change," Offerman explains.

Each operating situation calls for different technology, so each site is equipped with a standard package that is customized to address the site's unique needs. These vary depending on the production type in the area, the location, pressures and several other operating conditions, such as permitting regulations, weather and urban interface.

"In the Marcellus shale, the primary production mode is free-flowing wells," Offerman says. "But the terrain and the harsh winters make it very difficult for pumpers. SCADA and automated field operations allow us to optimize production and respond effectively to safety concerns—regardless of weather and terrain."

The company's use of autonomous systems extends beyond production sites to pipeline and transmission facilities. When a ground shift caused a pipeline to rupture, a low-static-pressure gauge reading initiated the automated local shutdown of two wells feeding into the pipeline, while data-communications software simultaneously triggered an alarm to production crews.

Without such a system, the well would have continued to feed the pipeline until field personnel recognized the problem and arrived to manually shut in the wells. The remote shut-in also prevented the wells from flowing at atmospheric pressure for an extended period of time, which could have caused an environmental incident.

"Many companies use SCADA to mitigate their unintended consequences," says Offerman. "We are not satisfied with that. We use it to maximize volumes, provide quality real-time information and avoid the possibility of unintended consequences." n

This article is reprinted with permission from "The Play," a quarterly publication of Chesapeake Energy Corp.